People and businesses in the oil and gas industry and, potentially, any industry involved in drilling into earthen formations, confront a number of important problems with respect to extraction of hydrocarbon fluids, gases, and other materials from underground reservoirs. These problems include, among others, the need to prevent the escape and loss of underground fluids and gases which are driven under pressure from the earthen formations and into the wellbore, the need to avoid contamination of, and damage to, the earthen formations and subterranean fluids and gases surrounding the wellbore, the need to seal wellbores in a manner which is noninvasive to the surrounding earthen formations upon completion of the drilling operation and the need to control the drilling apparatus so as to properly position the wellbore.
Control of the movement of underground fluids and gases into the wellbore during a drilling operation represents a particularly significant problem, both with respect to economic and safety-related issues.
Underground fluids and gases are typically under extreme pressure, referred to as “formation pressure.” This formation pressure causes surrounding fluids and gases to be driven from the underground production formations and reservoirs and into the wellbore positioned in the earthen formations surrounding the formations and reservoirs. If uncontrolled, these formation pressures cause oil, gas, water, brine and other subterranean materials to be forced into the wellbore and out onto surrounding ground surfaces or into the atmosphere.
As can be readily understood, the loss of these materials and the potential damage and contamination which can be caused by the uncontrolled flow of these materials is economically undesirable. Moreover, uncontrolled loss of flammable hydrocarbon materials from the pressurized production zone, can result in a condition known as a “wellbore blowout.” A wellbore blowout is highly undesirable because of the potential fire and explosion hazard created by the uncontrolled flow of flammable fluids and gases from the wellbore.
It is common industry practice to use drilling fluids and cement systems to attempt to control the potential loss of underground fluids and gases from the wellbore. These drilling fluids and cement systems are pumped directly into the wellbore where, it is anticipated, they will be deposited against the wellbore walls, thereby sealing those walls and limiting unwanted fluid and gas outflow. For example, prior art drilling fluids use a mechanism, known as filtration, to “screen out” or deposit wellbore cuttings and additives present in the drilling fluid against the wellbore walls. This layer, also called a “filter cake,” is deposited along the wellbore walls as the drilling fluid is forced by hydrostatic fluid column pressure, into the permeable earthen formations surrounding the wellbore. The additives may include polymers and viscosity modifiers which enable the fluid to support, or carry, the wellbore cuttings and other particulates prior to their screen out or deposition onto the wellbore face. A wide range of additives, including organic additives such as coconut husks and carbohydrate materials, have been used in combination with drilling fluids to seal the wellbores.
However, these drilling fluid systems are not complete solutions to the problem of unwanted fluid and gas loss from the wellbore. These drilling fluid systems are disadvantageous because they limit, but do not fully prevent, hydrocarbon loss. Drilling fluids are ineffective in forming a complete seal along the wellbore walls because the filter cake is permeable and is subject to dynamic erosion by the continuous circulation of the drilling fluid. Dynamic erosion is a continuous process of deposition and erosion which occurs during the drilling operation. In highly permeable earthen formations, this erosion can remove any filter cake and erode the surrounding earthen formation resulting in very poor seal formation during casing operations due to “wash-out,” or enlargement, of the wellbore.
Various cements, including Portland-type cements and cements including magnesium oxysulphate materials such as MAGNAPLUS brand cements available from B. J. Hughes, have also been used for sealing wellbore walls and for limiting the unwanted loss of fluids and gases from the earthen formations. These cement systems can be used in combination with the drilling fluid systems previously described. Such cements have been used for, among other things, grouting well casings, plugging abandoned wells and, occasionally, for sealing off permeable structures from adjacent fluids. As with the drilling fluids, the cement is typically pumped directly into the wellbore and into contact with the wellbore walls.
However, these cement systems have important disadvantages with respect to their use in wellbore operations. These limitations are due to the inherent physical properties of such materials and, importantly, their slow phase transition from a flowable to a solid state. Specifically, Portland-type cements and magnesium oxysulphate cements are thixotropic cements which form a gel structure during the transition between their slurry (i.e., flowable) and solid states. During this transition, and as the gel is formed, the cement slurry acquires a slight supportive strength. The increase in supportive strength reduces the hydrostatic pressure exerted by the cement fluid column on the geologically-exposed formations in the wellbore. The hydrostatic pressure created by the cement fluid column in the open wellbore is important because it is the only control factor to contain formation pressures. In the case of a pressurized zone, such as the production zone, the reduction in hydrostatic pressure of the cement fluid column can allow an influx of gases or fluids into the wellbore further reducing hydrostatic pressure. The cumulative loss in hydrostatic pressure can allow a sufficient influx of gases or fluids into the wellbore to cause an undesirable wellbore blow-out.
Another adverse consequence of the hydrostatic pressure reduction is referred to as “channelling.” Channelling occurs when fluids or gases transit through the gelled cement and form channels. These channels become part of the cement structure when the cement has set. The channels are highly disadvantageous because they allow leakage of gases and fluids through the channels even after the wellbore casing has been set and cemented. Such channelling often requires the use of expensive remedial clean up, fracturing or squeezing operations.
Not only are these prior art drilling fluid and cement systems incomplete solutions to the problem of preventing unwanted fluid and gas loss but they may also contribute to contamination and damage of earthen formations surrounding the wellbore and the fluid and gas reservoirs themselves. Contamination caused by drilling fluids and cements is referred to in industry as “invasiveness.” This type of contamination can occur because the use of drilling fluids is a dynamic process which can cause continuous fluid invasion of the permeable earthen formations surrounding the wellbore as the fluids are circulated within the wellbore. Once in the formations, the drilling fluid can then invasively interact with that formation to cause swelling, or dispersion, of reactive shales, or washout of unconsolidated sands, all of which can lead to wellbore instability and contamination of the surrounding hydrocarbon reservoirs.
Cement systems can also cause invasive contamination of the surrounding earthen formations, particularly as the cements are forced back into the formations by the hydrostatic pressure of the wellbore fluid column. Such contamination typically occurs during the time that the cement is in the gel, or flowable, phase. The cement filtrate, in particular, can be forced into the formation leaving solid, particulate material screened out against the wellbore face. The fluid forced back into the formation can cause problems such as water-wetting of preferentially oil-wet formations resulting in water blocking of the hydrocarbon fluids and gases.
It is well known and documented that such fluid filtrate invasion can cause damage to hydrocarbon-producing formations, or reservoirs, resulting in reduced production and/or expensive attempts at remedial operations to either remove, or bypass, the damage. This is particularly the case where production areas are concerned. In addition, the cement solid can be weaker because of the separation of the fluid filtrate from the particulate material. This condition can contribute to the undesirable loss of control over the flow of fluids and gases from the well bore.
These Portland-type and magnesium oxysulphate-based cement systems also have disadvantages with respect to removal of the hardened cement from the wellbore periphery—potentially resulting in further damage to the earthen formations. It is often necessary to remove the cement plug from the wellbore, for example in remedial operations. Magnesium oxysulphate-based cements can be solvated and removed with a solution containing about 15% hydrochloric acid (HCl). Such solvent is pumped directly into the wellbore to remove the cement. Portland cements are not soluble in a 15% HCl solution but can be solvated and removed with a stronger acid, such as hydrofluoric acid (HF). However, HF is undesirable because it can leave damaging deposits as a by-product of acidization.
However, acid solubility is irrelevant if the acid cannot come into contact with the cement or drilling fluid particulates. Prior art cement and drilling fluid system filtrates are often forced so far back into a formation that they cannot be contacted and solvated by the acid. The cement and drilling fluid particulates which cannot be removed remain in the earth as a potential contaminate. Invasive setting of concrete is a particular problem when seeking to reopen a wellbore which was sealed and closed for any reason. The well cannot be fully reopened by drilling out when the concrete has migrated back into the formation and the solvent solution cannot contact and solubilize the cement. In these cases, redrilling by side tracking is the usual remedy.
Sorel cements are another type of known cement. These cements contain magnesium oxychloride and have been used in applications such as for fire bricks and ornamental masonry where unpredictable pressure and temperature conditions are not applicable. These magnesium oxychloride cements have not been used in wellbore operations for many reasons including the inherent unpredictability of their setting properties. This is a major failing of these types of cements because operators must be able to calculate the amount of time that they have to work with the cement before it becomes a solid mass so as to be able to fully seal the wellbore or position equipment in the wellbore.
Specifically, when certain magnesium oxychloride cements are subjected to an increasing temperature/pressure gradient, they can become exothermically unstable. Under these conditions, the cement undergoes an exponential, non-linear, increase in internal temperature resulting in a runaway, or “flash set.” These cements are less than satisfactory precisely because the phase transition reaction occurs quickly, and without a predictable control parameter allowing predictable setting times. The reaction is so rapid that it is difficult to predictably control the setting of the cement even with use of retarding or accelerating compounds. In addition, certain of these magnesium oxychloride cements can have low compressive strengths and may degrade under conditions of high pressure. Other types of magnesium oxychloride cements are less reactive but undergo an extended gel phase before forming a solid. The gel phase is subject to all of the foregoing disadvantages including the disadvantages associated with invasiveness and channelling. Therefore, magnesium oxychloride cements have been deemed unacceptable for use in wellbore operations.
Yet another problem confronting the drilling industry involves the need to control the drilling apparatus in order to locate the wellbore in a predetermined position. For example, Portland-type cements are used for a drilling process known as “kickoff drilling.” In kick-off drilling operations, cement plugs are set in the wellbores of horizontal, multilateral and/or vertical wells. The drill is then used to partially drill through the plug. The drill is then kicked-off, or drilled-off of the plug at the required angle and direction into the surrounding formation.
A major problem can arise following this operation. For example, when drilling a well which is to be in a horizontal, or angled plane, the wellbore makes the transition to horizontal from vertical in what is known as a “build” section. In a build section the angle from the vertical is gradually increased in order to avoid sharp angles known as “dog legs.” Dog legs are problematic when running the drill string in or out of the hole. If the formation in the build section is soft, unstable or unconsolidated it can be eroded or “washed out” by the wellbore circulating fluids pumped down hole under pressure. In addition, any kind of fluid or gas influx in this area will exacerbate the tendency to wash out this area. Major difficulties can then be encountered when running in or pulling out of the hole and the drillstring may become stuck.
Portland cements are sometimes used in an attempt to stabilize this area. The cement may be either placed across the section or “squeezed” back into the formation. The cement is then drilled out. The problem then often arises of drilling out the cement “on track,” that is maintaining the same direction and angle as the original wellbore. When Portland cements are used, the drill string has a tendency to drill-off, or kick-off, the hard plug into the surrounding softer formation. In severe cases, the resultant dog legs in the wellbore can cause severe drag when running in or out of the hole and it may be impossible to run casing.
A far better method of controlling the drilling apparatus would be to provide a cement which could be easily drilled out when placed across these build sections and would prevent the kick-off situation from occurring. At the same time, the cement would have sufficient compressive strength to stabilize the surrounding section. As discussed, Portland type cements are often unsuitable for such an operation because of the hardness and chemical characteristics of the cement.
It would be a significant improvement in the art to provide an improved composition for limiting, or preventing, the influx of fluids or gases into the wellbore from the surrounding permeable formations, which would be non-invasive, which would be easily removable from the wellbore and other surrounding formations, which would allow the correct positioning of the drillstring and which would have predictable and controllable physical properties capable of permitting engineered application of the composition in a variety of environments and conditions.